WO2009105421A1 - Elimination améliorée de dioxyde de soufre (so2) à sec à partir de gaz de combustion - Google Patents

Elimination améliorée de dioxyde de soufre (so2) à sec à partir de gaz de combustion Download PDF

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Publication number
WO2009105421A1
WO2009105421A1 PCT/US2009/034274 US2009034274W WO2009105421A1 WO 2009105421 A1 WO2009105421 A1 WO 2009105421A1 US 2009034274 W US2009034274 W US 2009034274W WO 2009105421 A1 WO2009105421 A1 WO 2009105421A1
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WO
WIPO (PCT)
Prior art keywords
sorbent
flue gas
separator
outlet
directing
Prior art date
Application number
PCT/US2009/034274
Other languages
English (en)
Inventor
Armand A. Levasseur
George D. Mylchreest
Original Assignee
Alstom Technology Ltd
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Alstom Technology Ltd filed Critical Alstom Technology Ltd
Priority to MX2010007798A priority Critical patent/MX2010007798A/es
Priority to PL09712916T priority patent/PL2254684T3/pl
Priority to EP20090712916 priority patent/EP2254684B1/fr
Priority to CA2715450A priority patent/CA2715450C/fr
Priority to CN200980106201.7A priority patent/CN101980761B/zh
Publication of WO2009105421A1 publication Critical patent/WO2009105421A1/fr

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Classifications

    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/02—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by adsorption, e.g. preparative gas chromatography
    • B01D53/06—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by adsorption, e.g. preparative gas chromatography with moving adsorbents, e.g. rotating beds
    • B01D53/10—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by adsorption, e.g. preparative gas chromatography with moving adsorbents, e.g. rotating beds with dispersed adsorbents
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/34—Chemical or biological purification of waste gases
    • B01D53/46—Removing components of defined structure
    • B01D53/48—Sulfur compounds
    • B01D53/50—Sulfur oxides
    • B01D53/508—Sulfur oxides by treating the gases with solids
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/34—Chemical or biological purification of waste gases
    • B01D53/74—General processes for purification of waste gases; Apparatus or devices specially adapted therefor
    • B01D53/81—Solid phase processes
    • B01D53/83—Solid phase processes with moving reactants
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2251/00—Reactants
    • B01D2251/40—Alkaline earth metal or magnesium compounds
    • B01D2251/404—Alkaline earth metal or magnesium compounds of calcium
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2251/00—Reactants
    • B01D2251/60—Inorganic bases or salts
    • B01D2251/602—Oxides
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/30—Sulfur compounds
    • B01D2257/302—Sulfur oxides

Definitions

  • the present invention relates generally to fossil fuel fired heat generating systems that produce heat and sulfur dioxide (SO 2 ) laden flue gas. More particularly, the present invention relates dry scrubbers for removing SO 2 from the SO 2 laden flue gas produced by such heat generating systems.
  • SO 2 sulfur dioxide
  • Heat generating systems with furnaces for firing fossil fuels have long been employed to generate controlled heat, with the objective of doing useful work.
  • the work might be in the form of direct work, as with kilns, or might be in the form of indirect work, as with steam generators for industrial or marine applications or for driving turbines that produce electric power.
  • the sulfur in the fuel is oxidized to form SO 2 , which is exhausted in the flue gas leaving the furnace
  • An air pollution control (APC) subsystem is conventionally used to remove SO 2 and other so called pollutants, such as NO x and particulate matter including flyash, from SO 2 laden flue gas produced by such heat generating systems.
  • SO 2 and other so called pollutants such as NO x and particulate matter including flyash
  • the flue gas exhausted from the furnace of a coal fired heat generation system is directed to the APC subsystem.
  • the flue gas entering the APC subsystem is directed to APC components, each of which can be considered a system in its own right, in order remove the SO 2 and other so called pollutants from the flue gas.
  • the flue gas may be processed via a selective catalytic reduction (SCR) system (not shown) to remove NO x and via a dry or semi-dry SO 2 scrubber system, such as a flash dryer absorber (FDA), to remove SO 2 and particulate matter.
  • SCR selective catalytic reduction
  • FDA flash dryer absorber
  • FIG. 1 depicts an FDA 10 for scrubbing SO 2 from the flue gas produced in the burning of fossil fuel.
  • the SO 2 laden flue gas 12 is processed by an absorber tower 14 to capture the SO 2 in the SO 2 laden flue gas.
  • the SO 2 in the flue gas has a high acid concentration.
  • the absorber tower 14 creates an environment in which the SO 2 laden flue gas is placed in contact, under the proper conditions, with material having a higher pH level than that of the flue gas in order to capture, i.e. absorb, the SO 2 from the SO 2 laden flue gas, so that a desulfurization of the flue gas will occur.
  • the residual content of calcium oxide (CaO), which is commonly referred to as lime, in the flyash within the flue gas can be used as the sorbent.
  • CaO calcium oxide
  • the absorber tower 14 such that the SO 2 in the SO 2 laden flue gas 12 is absorbed by the residual CaO in the flyash.
  • the flue gas 12a which includes the flyash with the transformed sorbent, is exhausted from the absorber tower 14 to a baghouse 16 or alternatively an electrostatic precipitator (ESP) (not shown).
  • ESP electrostatic precipitator
  • the baghouse 16 functions to separate the flyash from the flue gas 12a, to thereby remove the flyash with the absorbed SO 2 from the flue gas 12c that flows downstream of the baghouse. From the baghouse 16, the flue gas 12c can, if desired, be directed to downstream processing equipment (not shown), but will ultimately be directed to an exhaust stack (also not shown). Beneficially, at least a portion of the separated flyash 12b is directed from the baghouse 16, via a feeder 20, depicted as a rotary feeder, driven by motor 22, for recycling. The feeder 20 directs the flyash 12b to a hydrator 25, depicted as including a mixer 24 driven by motor 26, where it is partially hydrated, i.e.
  • the flyash with absorbed SO 2 is then separated from the flue gas by a baghouse or ESP, and at least a part of the separated fly ash is feed to a hydrator and rehydrated to a less than desirable humidity level for SO 2 capture, before being recycled back to the absorber tower.
  • a system for removing sulfur dioxide (SO 2 ) from SO 2 laden flue gas resulting from the burning of fossil fuel, for example from the burning of coal in a furnace includes an absorber and first and second separators.
  • the absorber which could for example take the form of what is often characterized as a reactor or absorber tower, is configured to capture SO 2 from a flow of the SO 2 laden flue gas with a sorbent. More particularly, the absorber is configured to provide an environment and to direct the SO 2 laden flue gas and the sorbent in a manner that induces the capture of SO 2 .
  • Such a configuration is well understood in the art.
  • the flow of the SO 2 laden flue gas will typically include flyash, and the flyash may in turn include the sorbent, such as calcium oxide (CaO), that will be used to capture the SO 2 .
  • the relative humidity of the sorbent in the absorber is greater than 50%.
  • the capture of the SO 2 from the flow of the SO 2 laden flue gas by the sorbent may, for example, transform the CaO, which is commonly referred to as lime, into calcium sulfite (CaSO 3 ).
  • the first separator which is preferably a cyclone type separator, is configured to separate a first portion of the sorbent with the captured SO 2 from a second portion of sorbent and also from the flue gas.
  • the sorbent with captured SO 2 is separated such that an average size of sorbent particles in the first portion of sorbent is larger than an average size of sorbent particles in the second portion of sorbent.
  • the second separator which is preferably either a baghouse or electrostatic precipitator type separator, is configured to separate the second portion of sorbent from the flue gas.
  • the absorber includes (i) an absorber inlet for receiving the flow of SO 2 laden flue gas, and (ii) an absorber outlet for directing the flue gas and the sorbent with the captured SO 2 from the absorber.
  • the first separator includes (i) a first separator inlet for receiving the flue gas and the sorbent directed from the absorber, (ii) a first separator flue gas outlet for directing the flue gas and the second portion of sorbent from the first separator, and (iii) a first separator sorbent outlet for directing the first portion of sorbent from the first separator.
  • the second separator includes (i) a second separator inlet, for receiving the flue gas and the second portion of sorbent directed from the first separator, (ii) a second separator flue gas outlet for directing the flue gas from the second separator, and (iii) a second separator sorbent outlet for directing the second portion of sorbent from the second separator.
  • the system includes a hydrator, which could take the form of a tank and mixer, configured to rehydrate the first portion of sorbent directed from the first separator. It will be recognized that the first portion of sorbent will have a particular chemical composition. If desired, the hydrator can be further configured to combine the first portion of sorbent with a material having a different chemical composition. For example, the first portion of sorbent might be combined with a different type sorbent, e.g. hydrated fresh lime, or an additive, e.g. activated carbon, by the hydrator.
  • a hydrator which could take the form of a tank and mixer, configured to rehydrate the first portion of sorbent directed from the first separator. It will be recognized that the first portion of sorbent will have a particular chemical composition. If desired, the hydrator can be further configured to combine the first portion of sorbent with a material having a different chemical composition. For example, the first portion of sorbent might be combined with a different type sorbent,
  • the hydrator includes an outlet for directing the rehydrated sorbent to the absorber.
  • the hydrator may also be further configured to also rehydrate the second portion of sorbent directed from the second separator.
  • the system may include a reheater configured to heat the flue gas and the second portion of sorbent. If so, the reheater heats the flue gas and the second portion of sorbent directed from the first separator.
  • the reheater has a third outlet for directing the heated flue gas and the heated second portion of sorbent from the reheater to the second separator.
  • the second portion of sorbent and the flue gas separated by the second separator are the heated second portion of sorbent and the heated flue gas directed from the reheater.
  • Figure 1 depicts a conventional SO 2 removal system configuration, including an flash dry absorber (FDA) for capturing and removing SO 2 from SO 2 laden flue gas exhausted from a furnace of a fossil fuel fired heat generating system.
  • FDA flash dry absorber
  • Figure 2 is a graph depicting the effect of the relative humidity of a sorbent on the efficiency of the absorption of SO 2 from SO 2 laden flue gas exhausted from a furnace of a fossil fuel fired heat generating system.
  • Figure 3 depicts a SO 2 removal system configuration, including a FDA for capturing and removing SO 2 from SO 2 laden flue gas exhausted from a furnace of a fossil fuel fired heat generating system, in accordance with the present invention.
  • Figure 2 is a graph depicting data from testing performed with a conventional flash dry absorber (FDA). While the graph will be self explanatory to those skilled in the art, it is perhaps worthwhile to highlight that, as evidenced by the test results, if the relative humidity of the sorbent can be increased above the 50% level, the overall SO 2 capture performance can be increased dramatically. Furthermore, testing has shown that more than 95% of the sulfur capture reaction in a conventional FDA, and hence the capture of SO 2 from SO 2 laden flue gas exhausted from a furnace of a fossil fuel fired heat generating system, occurs in the absorber tower, with little if any capture occurring in the baghouse or ESP.
  • FDA flash dry absorber
  • FIG. 3 depicts FDA 300 in accordance with an embodiment of the present invention.
  • the FDA 300 can itself be considered a system, i.e. an FDA system.
  • the FDA 300 could also be considered a component of an air pollution control (APC) subsystem of a heat generating system, when implemented to remove SO 2 from SO 2 laden flue gas produced by such a heat generating system.
  • APC air pollution control
  • the flue gas entering the APC subsystem may have been directed to one or more other APC components upstream of the FDA 300.
  • the flue gas may have been processed by a selective catalytic reduction (SCR) component of the APC subsystem (not shown) to remove NO x prior to being directed to the FDA 300.
  • SCR selective catalytic reduction
  • the flue gas leaving the FDA 300 may be directed to one or more other APC components downstream of the FDA for further processing before being exhausted from an exhaust stack.
  • a flow of SO 2 laden flue gas 312 is received via an absorber inlet and processed by the absorber tower 314 to capture the SO 2 in the SO 2 laden flue gas.
  • the SO 2 in the flue gas 312 has a high acid concentration. Accordingly, to capture the SO 2 , the absorber tower 314 creates an environment in which the SO 2 laden flue gas 312 is placed in contact, under the proper conditions, with sorbent having a higher pH level than that of the flue gas in order to capture, i.e.
  • the sorbent absorbs, the SO 2 from the SO 2 laden flue gas, so that a desulfurization of the flue gas 312 will occur.
  • CaO calcium oxide
  • the flyash within the flue gas 312 is used as the sorbent, although this is not mandatory and it should be understood that a different sorbent could conjunctively or alternatively be used.
  • the relative humidity of flyash, and hence the sorbent, in the absorber tower 314 is maintained at over 50% relative humidity. It will be understood from Figure 2 that the greater the relative humidity of the flyash, and thus the sorbent, above the 50% threshold, the more efficient the capture of the SO 2 by the sorbent and therefore the better the performance of the absorber tower 314.
  • the flue gas 312a which includes the flyash with the transformed sorbent, is exhausted from the absorber tower 314 via an absorber outlet to a first separator 350.
  • the first separator 350 is preferably a mechanical separator such as the cyclone, as shown in Figure 3, although this is not mandatory and another type separator could be utilized.
  • the first separator 350 functions to receive the flue gas 312a via an inlet and to separate one portion of the flyash in the flue gas 312a both from another portion of the flyash in the flue gas 312a and from the flue gas itself.
  • the one portion will be referred to as a first portion 312b and has particles of a larger average particle size and greater average relative humidity, while the other portion will be referred to as a second portion 312c and has particles of a smaller average particle size, e.g. fines, and lower average relative humidity.
  • the first portion of flyash 312b is removed from the flue gas 312d with the second portion of flyash 312c that flows downstream from the first separator, thereby removing a portion of the flyash and captured SO 2 from the flue gas that flows from the first separator 350.
  • the flue gas 312d with the second portion 312c of flyash is directed downstream via first separator flue gas outlet to a second separator 316, which is preferably a baghouse, as shown in Figure 3, or electrostatic precipitator (ESP) (not shown), but could alternatively be some other type of separator.
  • the separated first portion of flyash 312b is directed from the first separator 350, via a first separator sorbent outlet, to a feeder 320, depicted in Figure 3 as a rotary feeder, driven by motor 322, for recycling.
  • the feeder 320 directs the separated first portion of flyash 312b to a hydrator 325, depicted as including a mixer 324 driven by motor 326, where it is partially hydrated, i.e. humidified, with water (H 2 O), to a relative humidity that will ensure that the relative humidity of the flyash in the absorber tower 314, i.e. of the combined flyash in the incoming flow of flue gas 312 and recycled flyash in the incoming flow of the hydrated flyash stream 328, will be at the desired level, which preferably exceeds 50% relative humidity.
  • a hydrator 325 depicted as including a mixer 324 driven by motor 326, where it is partially hydrated, i.e. humidified, with water (H 2 O), to a relative humidity that will ensure that the relative humidity of the flyash in the absorber tower 314, i.e. of the combined flyash in the incoming flow of flue gas 312 and recycled flyash in the incoming flow of the hydrated flyash stream 328, will be
  • the first portion of flyash 312b will be partially hydrated in the hydrator 325 such that it has a relative humidity well over 50%, before being directed from the hydrator 325 via a hydrator outlet in the recycled hydrated flyash stream 328 to the absorber tower 314.
  • a reheater 370 is included in the FDA between the first separator 350 and the second separator 316 in order to control the relative humidity of the flue gas 312d with the second portion of flyash 312c that enters the second separator 316, via a second separator inlet.
  • the flue gas 312d with the second portion of flyash 312c can be sufficiently heated to remove excess moisture before entering the second separator, should this be required to, for example, prevent bag binding, cold spot condensation or other related problems.
  • reheater 370 is included, the flue gas 312d with the second portion of flyash 312c directed from the first separator is received via a reheater inlet, heated, and then directed via a reheater outlet to the second separator inlet.
  • the second separator 316 functions to separate the second portion of flyash 312c, which has the smaller particles and lower relative humidity, from the flue gas 312d. This separation removes the vast majority, if not all, of the remainder of the flyash and captured SO 2 from the flue gas 312e that is directed, via a second separator flue gas outlet, to flow downstream of the second separator 316. From the second separator 316, the separated flue gas 312e may be directed to further downstream processing equipment (not shown) and is ultimately directed to an exhaust stack (also not shown). The separated second portion of flyash 312c is directed, via a second separator sorbent outlet, to a screw conveyor bottom 318. It should be understood that an air slide bottom or some other form of bottom could be used in lieu of the screw conveyor bottom 318 driven by motor 319.
  • a diverter 375 which is depicted in Figure 3 as a modulating diverter valve, can be included in the FDA 300. If recycling of the second portion of flyash 312c along with the first portion of flyash 312b is desired, the diverter 375 can be operated to direct all or part of the separated second portion of flyash, which is identified as flyash 312c', to the hydrator 325, where it will be combined and partially hydrated with the first portion of flyash 312b, before being recycled back to the absorber tower 314, via the hydrated stream 328.
  • the diverter 375 can be operated to direct some or all of the separated second portion of flyash 312c to a flyash disposal area 332 via waste stream 330.
  • the first portion of flyash which has a particular chemical composition, may be combined in the hydrator with a material having a different chemical composition.
  • the present invention facilitates the use of sorbent with higher, e.g. over 50%, relative humidity and thus improved SO 2 capture efficiency, while avoiding flyash handling problems, binding in the baghouse or ESP, and cold spot condensation problems. Furthermore, if a baghouse is utilized for the second separator, the design requirements, such as air-to-cloth ratio and bag strength, can be relaxed considerably due to much lower, e.g. by a factor of up to 50, solids loading entering the baghouse, and therefore the cleaning cycles can also be reduced. Additionally, an air slide bottom is unnecessary on the baghouse.

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  • Chemical & Material Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Environmental & Geological Engineering (AREA)
  • Analytical Chemistry (AREA)
  • General Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Health & Medical Sciences (AREA)
  • Biomedical Technology (AREA)
  • Dispersion Chemistry (AREA)
  • Treating Waste Gases (AREA)

Abstract

Un système (300) destiné à éliminer le dioxyde de soufre (SO2) des gaz de combustion chargés en SO2 qui résultent de la combustion de combustible fossile, comprend un absorbeur (314) et des premier et deuxième séparateurs (350), (316). L'absorbeur capture le SO2 dans un flux de gaz de combustion chargés en SO2 (312) avec un sorbant. Le premier séparateur (350) sépare une première partie (312b) du sorbant avec le SO2 capturé, à la fois d'une deuxième partie (312c) du sorbant avec le SO2 capturé et des gaz de combustion (312). Le deuxième séparateur (316) sépare la deuxième partie (312c) du sorbant des gaz de combustion (312e).
PCT/US2009/034274 2008-02-18 2009-02-17 Elimination améliorée de dioxyde de soufre (so2) à sec à partir de gaz de combustion WO2009105421A1 (fr)

Priority Applications (5)

Application Number Priority Date Filing Date Title
MX2010007798A MX2010007798A (es) 2008-02-18 2009-02-17 Mejorada depuracion de dioxido de azufre (so2) seco en gas de combustion.
PL09712916T PL2254684T3 (pl) 2008-02-18 2009-02-17 Ulepszone usuwanie suchego dwutlenku siarki (SO2) ze spalin
EP20090712916 EP2254684B1 (fr) 2008-02-18 2009-02-17 Élimination améliorée de dioxyde de soufre (so2) à sec à partir de gaz de combustion
CA2715450A CA2715450C (fr) 2008-02-18 2009-02-17 Elimination amelioree de dioxyde de soufre (so2) a sec a partir de gaz de combustion
CN200980106201.7A CN101980761B (zh) 2008-02-18 2009-02-17 改进的来自烟气的干式二氧化硫(so2)洗涤

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
US2938808P 2008-02-18 2008-02-18
US61/029,388 2008-02-18
US12/371,705 US7850936B2 (en) 2008-02-18 2009-02-16 Dry sulfur dioxide (SO2) scrubbing
US12/371,705 2009-02-16

Publications (1)

Publication Number Publication Date
WO2009105421A1 true WO2009105421A1 (fr) 2009-08-27

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PCT/US2009/034274 WO2009105421A1 (fr) 2008-02-18 2009-02-17 Elimination améliorée de dioxyde de soufre (so2) à sec à partir de gaz de combustion

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US (1) US7850936B2 (fr)
EP (1) EP2254684B1 (fr)
CN (1) CN101980761B (fr)
CA (1) CA2715450C (fr)
MX (1) MX2010007798A (fr)
PL (1) PL2254684T3 (fr)
WO (1) WO2009105421A1 (fr)

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EP3002051B1 (fr) * 2014-10-03 2019-12-25 General Electric Technology GmbH Séparateur de poussière utile avec système d'épuration à sec
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WO2018229589A1 (fr) 2017-06-16 2018-12-20 Chevron U.S.A. Inc. Procédés et systèmes pour éliminer des contaminants à partir d'un gaz de combustion d'un navire ou d'un vaisseau flottant en mer à l'aide d'un dispositif à lit fixe rotatif
CN113441007A (zh) * 2021-07-23 2021-09-28 河北领阔环保科技有限公司 一种活性炭一体化脱硫脱硝系统

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Also Published As

Publication number Publication date
US20090208397A1 (en) 2009-08-20
CN101980761A (zh) 2011-02-23
PL2254684T3 (pl) 2015-07-31
EP2254684B1 (fr) 2015-04-08
CA2715450C (fr) 2013-01-08
MX2010007798A (es) 2010-08-10
CN101980761B (zh) 2014-12-17
US7850936B2 (en) 2010-12-14
CA2715450A1 (fr) 2009-08-27
EP2254684A1 (fr) 2010-12-01

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